In underground drilling, such as gas, oil or geothermal drilling, a bore is drilled through a formation deep in the earth. Such bores are formed by connecting a drill bit to sections of long pipe, referred to as a “drill pipe,” so as to form an assembly commonly referred to as a “drill string” that extends from the surface to the bottom of the bore. The drill bit is rotated so that it advances into the earth, thereby forming the bore. In rotary drilling, the drill bit is rotated by rotating the drill string at the surface. In directional drilling, the drill bit is rotated by a down hole mud motor coupled to the drill bit; the remainder of the drill string is not rotated during drilling. In a steerable drill string, the mud motor is bent at a slight angle to the centerline of the drill bit so as to create a side force that directs the path of the drill bit away from a straight line. In any event, in order to lubricate the drill bit and flush cuttings from its path, piston operated pumps on the surface pump a high pressure fluid, referred to as “drilling mud,” through an internal passage in the drill string and out through the drill bit. The drilling mud then flows to the surface through the annular passage formed between the drill string and the surface of the bore.
Depending on the drilling operation, the pressure of the drilling mud flowing through the drill string will typically be between 1,000 and 25,000 psi. In addition, there is a large pressure drop at the drill bit so that the pressure of the drilling mud flowing outside the drill string is considerably less than that flowing inside the drill string. Thus, the components within the drill string are subject to large pressure forces. In addition, the components of the drill string are also subjected to wear and abrasion from drilling mud, as well as the vibration of the drill string.
The distal end of a drill string, which includes the drill bit, is referred to as the “bottom hole assembly.” In “measurement while drilling” (MWD) applications, sensing modules in the bottom hole assembly provide information concerning the direction of the drilling. This information can be used, for example, to control the direction in which the drill bit advances in a steerable drill string. Such sensors may include a magnetometer to sense azimuth and accelerometers to sense inclination and tool face.
Historically, information concerning the conditions in the well, such as information about the formation being drill through, was obtained by stopping drilling, removing the drill string, and lowering sensors into the bore using a wire line cable, which were then retrieved after the measurements had been taken. This approach was known as wire line logging. More recently, sensing modules have been incorporated into the bottom hole assembly to provide the drill operator with essentially real time information concerning one or more aspects of the drilling operation as the drilling progresses. In “logging while drilling” (LWD) applications, the drilling aspects about which information is supplied comprise characteristics of the formation being drilled through. For example, resistivity sensors may be used to transmit, and then receive, high frequency wavelength signals (e.g., electromagnetic waves) that travel through the formation surrounding the sensor. By comparing the transmitted and received signals, information can be determined concerning the nature of the formation through which the signal traveled, such as whether it contains water or hydrocarbons. Other sensors are used in conjunction with magnetic resonance imaging (MRI). Still other sensors include gamma scintillators, which are used to determine the natural radioactivity of the formation, and nuclear detectors, which are used to determine the porosity and density of the formation.
In traditional LWD and MWD systems, electrical power was supplied by a turbine driven by the mud flow. More recently, battery modules have been developed that are incorporated into the bottom hole assembly to provide electrical power.
In both LWD and MWD systems, the information collected by the sensors must be transmitted to the surface, where it can be analyzed. Such data transmission is typically accomplished using a technique referred to as “mud pulse telemetry.” In a mud pulse telemetry system, signals from the sensor modules are typically received and processed in a microprocessor-based data encoder of the bottom hole assembly, which digitally encodes the sensor data. A controller in the control module then actuates a pulser, also incorporated into the bottom hole assembly, that generates pressure pulses within the flow of drilling mud that contain the encoded information. The pressure pulses are defined by a variety of characteristics, including amplitude (the difference between the maximum and minimum values of the pressure), duration (the time interval during which the pressure is increased), shape, and frequency (the number of pulses per unit time). Various encoding systems have been developed using one or more pressure pulse characteristics to represent binary data (i.e., bit 1 or 0)—for example, a pressure pulse of 0.5 second duration represents binary 1, while a pressure pulse of 1.0 second duration represents binary 0. The pressure pulses travel up the column of drilling mud flowing down to the drill bit, where they are sensed by a strain gage based pressure transducer. The data from the pressure transducers are then decoded and analyzed by the drill rig operating personnel.
Various techniques have been attempted for generating the pressure pulses in the drilling mud. One technique involves incorporating a pulser into the drill string in which the drilling mud flows through passages formed by a stator. A rotor, which is typically disposed upstream of the stator, is either rotated continuously, referred to as a mud siren, or is incremented, either by oscillating the rotor or rotating it incrementally in one direction, so that the rotor blades alternately increase and decrease the amount by which they obstruct the stator passages, thereby generating pulses in the drilling fluid. An oscillating type pulser valve is disclosed in U.S. Pat. No. 6,714,138 (Turner et al.), hereby incorporated by reference in its entirety. A prior art rotor used in a commercial embodiment of U.S. Pat. No. 6,714,138 (Turner et al.) is shown in FIG. 1. In that embodiment, the rotor was located upstream of the stator, as shown in U.S. Pat. No. 6,714,138 (Turner et al.), and was oriented with respect to the direction of the flow of drilling mud so that the downstream surface of the blade was a flat surface, with the upstream surface of the blade tapering so that the thickness at the radial tip of the blade was about ⅛ inch (3 mm).
Unfortunately, in such prior pulsers, the flow of drilling mud creates pressure forces that tend to drive the rotor into a position in which the rotor blades provide the maximum obstruction to the flow of drilling mud. Consequently, if the motor driving the pulser fails, the flow induced torque will cause the rotor to remain stationary in the position of maximum obstruction, thereby interfering with flow of drilling mud, increasing the pressure of the drilling mud, and accelerating wear of the pulser components due to the high flow velocity through the obstructed passages.
Moreover, even if the motor does not fail, during periods when the pulser is not operating, the flow induced torque will gradually overcome the rotor's resistance to rotation and obstruct the mud flow. Since this unnecessary obstruction to the flow of drilling mud is undesirable, the rotor position must be monitored and the pulser motor periodically employed to rotate the rotor into the position of minimum obstruction. This results in an unnecessary drain on the battery that powers the motor.
According to one approach, described in U.S. Pat. No. 4,785,300 (Chin et al), the generation of a flow induced torque tending to rotate the rotor into the obstruction orientation may be prevented in certain pulsers by shaping rotor blades, located downstream of the stator, so that their sides are outwardly tapered, and thus become wider in the circumferential direction, as they extend in the downstream direction. However, this approach is not believed to be entirely satisfactory in many situations.
Consequently, it would be desirable to provide a mud pulse telemetry system in which the rotor blades were prevented from unintentionally rotating into the obstructed position when the pulser was not being utilized to transmit information, without the need to operate the pulser motor.
In addition, the portions of a pulser subject to the high velocity flow of drilling mud are subject to wear. Consequently, it would also be desirable to develop a pulser with increased resistance to wear in such high flow areas.